Natural gas is becoming a very attractive fuel from both environmental and economic perspectives. In most instances of recovery from its source in its natural state, the natural gas will be relatively warm from its subterranean locations, and “wet”, that meaning that it will contain moisture. Transportation of natural gas from its source thus can be as dry gas transportation, where the gas is dehydrated prior to transporting in a pipeline, or directly as wet gas transportation before dehydrating. Dry gas transportation is preferred since it can avoid a series of problems caused in wet gas transportation, such as, internal corrosion and hydrate formation. This approach does however require that drying process facilities be located near the source. However, significant numbers of natural gas reservoirs are located offshore, which requires costly offshore facilities to dehydrate the wet gas to dry gas Therefore, wet gas direct transportation from offshore reservoirs to onshore facilities can result in a significant cost savings. This direct transportation is generally conducted in transportation pipelines that are called “wet gas pipelines”. These pipelines can be large in diameter, upwards of 30″ (76.2 cm.) diameter, and in use have a substantial gas volume in the upper portion of the wet gas pipelines. But in addition, a small amount of liquids (water, condensate, and dissolved acid gases) are often present as a liquid phase at the bottom of the pipeline, and even sometimes as entrained moisture particles within the gas volume.
Further, since wet gas pipelines contain moisture laden gas, water can condense out near the top and upper sides of the pipeline when heat transfer occurs due to temperature gradients between that of the warm wet gas and the ambient pipeline temperature when routed through cold surroundings, such as subsea or arctic locations, etc. Wet gas pipelines are typically constructed of alloy steel for strength/cost reasons, and corrosion is often experienced to occur at both the bottom and the top of the pipe. Corrosion at the top of the pipeline occurs due to the above condensation on the exposed pipeline surface, and will be referred to herein as “Top of the Line Corrosion” (TOLC or TOL corrosion). The corrosion at the bottom of the pipeline is due to the liquids flowing along the bottom of the gas pipeline and will be referred to herein as “Bottom of the Line Corrosion” (BOLC or BOL corrosion). Both TOLC and BOLC will depend on the temperature variation between the gas in the pipeline and the outside temperature (affecting the condensation rate) and the additional presence of naturally occurring acid gases in the natural gases, such as CO2, H2S, and organic acids. TOLC can be more severe than BOLC since condensed liquid at the top of the pipeline cannot be easily or effectively modified with corrosion inhibitors that can be used at the bottom of the lines.
Thus mitigating TOL corrosion in wet gas pipelines is challenging. As noted above, corrosion inhibitor chemicals can be injected into wet gas pipelines to mitigate BOL corrosion that occurs due to the flow of condensed liquids and/or water at the bottom of the pipeline. However, it is difficult to continuously apply inhibitors to the top of the line especially in a stratified flow regime, where water or liquids with inhibitor only flow at the bottom of the line. So, in areas where pipeline condensation occurs, TOL corrosion is typically more severe. This is because of more aggressive water chemistry top of the line, coupled with an inability to effectively treat, that occurs with the stratified flow regime found in wet gas pipelines.
There are several existing strategies for mitigating TOL corrosion. First, batch corrosion inhibition may be used, where a slug of inhibited liquids is pushed through the line with one or more “pigs”, solid objects sized to fit closely within the pipeline. In this approach, the corrosion inhibitor is delivered to the top of the pipe because the liquid slug largely fills the pipe ahead of the pig. To be effective, this method of batch corrosion inhibition must be conducted at regular intervals to reapply the corrosion inhibitor. Second, the pipeline may be operated in a flow regime where entrained liquid is delivered to the top of the pipe (e.g., slug flow and/or increased gas flow rates). In this approach, there must be enough inhibitor in the entrained liquid to mitigate corrosion at the top of the pipe and the pipeline must be operating at high flow rates. Third, one or more sections of the pipeline may be constructed from or lined with a corrosion resistant alloy (CRA) and located where the majority of the condensation occurs, for example at the entrance to the pipeline at the source. The remainder of the pipeline may be constructed from carbon or low alloy steel if the condensation rates in other regions are low enough to reduce the occurrence of TOL corrosion.
Developing methods and apparatus for testing or monitoring TOL corrosion of wet gas pipelines is very important. Top of the line corrosion testing may be used to measure corrosion rates for the design of wet gas pipelines and to identify mitigation strategies. Top of the line corrosion monitoring devices may be used to confirm that mitigation strategies are working or as guidance for determining inspection intervals of wet gas pipelines. Typical corrosion testing apparatus, such as atmospheric cells, high pressure, high temperature (HPHT) autoclaves, or flow loops, do not adequately represent the top of the line conditions. In these types of tests, corrosion coupons, specimens and/or probes are generally submersed in an aqueous solution and exposed to the partial pressures of the acids gases. This lead to a much greater solution volume to pipeline surface area than would be present at the top of an operating or flowing pipeline and does not accurately reproduce the condensation phenomenon. Further, it has proven difficult to accurately capture the key features of the top of the line corrosion in laboratory equipment so a need exists in the art to address this difficulty.